A multitude of wells have been drilled into various subterranean formations for the exploration and extraction of oil, gas, and other material therefrom. Typically, these wells are constructed through the utilization of a rotary drilling system including a plurality of connected drill pipe commonly referred to as the drill string, operatively connected to a rotary drill bit. As the rotary drill bit drills through the subterranean formation, drilling fluid is pumped from a pumping unit on the surface of the earth down the drill string and through ports provided in the drill bit to the well bottom and circulated back to the surface through the annulus formed about the drill string.
Drilling fluids are employed in the drilling system for a multitude of reasons including cooling and/or lubricating the drill bit and circulating the cuttings from the wellbore. Additionally, drilling fluids are utilized to maintain hydrostatic pressure on the subterranean formation through which the wellbore is drilled in order to prevent pressurized formation fluid from entering the wellbore.
Typically, wells are drilled into subterranean formations including sedimentary rock. Sedimentary rock in general has pores and can be permeable. In general, drilling fluid or drilling mud includes clay particles, fluid loss control agents and other additives in a liquid such as water or oil. In ordinary conditions, many of the clay particles are larger than the pores. When drilling mud contacts a newly created portion of a wellbore wall during drilling, the drilling fluid, driven by pressure differentials, will start to enter the pores in the wall. However, the larger clay particles that cannot enter the pores will together with the fluid loss control agents form a tight drilling fluid filter cake on the permeable wall to stop any clay particles from further entering the formation and to substantially slow down the liquid entering the formation. The amount of fluid lost into the formation before the tight drilling fluid filter cake on the wall is formed is commonly called “spurt loss,” wherein the fluid may contain some fine clay particles and the liquid. After the drilling fluid filter cake is formed, the fluid lost to the formation through the cake is only the liquid.
Conventional drilling fluids have been designed to minimize the spurt loss and the fluid loss into porous formations by forming tight drilling fluid filter cakes. During normal drilling, almost all drilling fluid pumped down hole will be circulated back to surface and there is only a minimum amount of drilling fluid lost into formations. However, conventional designs still fail to stop drilling fluid losses when the pores are too large for any clay particles to plug. Typically, in such instances, no filter cake can form and the drilling fluid, including the clay particles and the liquid, will flow away from the wellbore into the formations rather than circulate back to surface. This is commonly referred to as “lost circulation” or “lost returns.” Similarly, lost circulation may also happen when large open fractures or vugs are encountered during drilling. The wellbore interval where drilling fluid is lost is often referred to as a “lost circulation zone.”
In addition, a wellbore may simply not be sufficiently competent to support the pressure applied by the drilling fluid and may break down under this pressure and allow the drilling fluid to flow away into the formation through generated fractures. This may occur when the wellbore integrity has been exceeded by the wellbore pressure. Such instances can occur when the weight of the drilling fluid provided creates a higher hydrostatic pressure than the wellbore can support. In such instances, the wellbore is not able to contain this much pressure and typically fractures, thereby allowing the drilling fluid to flow into the formation. The maximum pressure a wellbore can contain is referred to as wellbore pressure containment. When the wellbore pressure containment of a wellbore is improved, the wellbore is strengthened and behaves stronger. Therefore, improving wellbore pressure containment sometimes is referred to as wellbore strengthening.
The hydrostatic pressure in the well is in part determined by the weight (or density) of the drilling fluid used. The weight of the drilling fluid is important as it determines the hydrostatic pressure in the wellbore at any given depth, which prevents the formation fluid such as hydrocarbon or water from flowing into the wellbore and prevent a well blowout in extreme cases. Additionally, the weighted drilling fluid provides assistance in keeping the walls of the wellbore from collapsing while drilling. While the drilling fluid is circulating upward in the annulus in the wellbore, friction of the drilling fluid against the wellbore walls creates additional pressure to the wellbore. Thus, drilling operations often consider equivalent circulating density (ECD) of a drilling fluid, which is equivalent to the circulating friction pressure in the annulus, plus the static head of the fluid due to the density of the fluid.
Conventionally, a section of wellbore is drilled to the depth where the ECD creates a wellbore pressure approaching the wellbore integrity before action is taken to prevent fracturing. For example, intervals of the wellbore may contain weak or lost circulation formations above a permeable high pressure formation. In such an instance, a lower weight drilling fluid may be employed in the drilling process and steel casing strings of sequentially reducing diameters may be installed in the wellbore to protect the weaker zones above the permeable high pressure zone. Such casing strings are provided so that higher weight drilling fluid may be used in the permeable high pressure formation intervals without allowing for drilling fluid to fracture the weak or lost circulation formations. Stopping the drilling process to run casing in the well is very costly and time consuming. Additionally, each casing string added has a smaller diameter than the previous string, which may create impractical well dimensions depending on the number of casing strings needed to complete the well. In such cases, the reduced hole diameter created by the casing strings may create an impractical drilling situation. If a higher weight drilling fluid could be used in these weaker zones without the weaker zones being protected by steel casing, a well could be drilled into the higher and deeper high pressure zones with less casing. Elimination of one or more casing strings from a well can provide important savings in time, material and costs of drilling the well.
As mentioned above, drilling fluids can enter the formation through a fracture, either a pre-existing fracture or a fracture induced by the hydraulic pressure created in the wellbore during the drilling process. Commonly, drilling fluids employed are oil, synthetic or water based. These fluids are treated to provide desired rheological properties which make the fluids particularly useful in the drilling of wells. Generally, drilling fluid does not contain large particles capable of blocking and/or sealing the fractures and often fails to stop lost circulation. Intuitively, large particles, commonly referred to as Lost Circulation Material (LCM) sometimes are arbitrarily added to regular drilling fluid in attempt to plug fractures for preventing or curing lost circulation. Such particles added to the drilling fluid can include calcium carbonate, sand, coke, nut hulls, corn cobs, fiber, paper, ground paper, asphalt, wood chips, engineering plastics, pistachio hulls, almond hulls, peanut hulls, clay, and weighting materials such as barite and hematite. After being added with some larger particulates, a fluid may become a particulate fracture sealing fluid.
For at least the foregoing reasons including retaining the formation fluid in the formation and preventing the wellbore from collapsing, it is advantageous for a hydrocarbon well to contain high pressure in the wellbore during the drilling process. The ability of a wellbore to contain pressure is largely defined by the stress that holds the wellbore against being inflated and eventually fractured by wellbore pressure. In a subterranean formation, stresses naturally exist. Stresses in different formations can vary greatly in magnitude. Additionally, after a circular wellbore is created in a stressed formation, the stress field then is re-disturbed around the wellbore and a concentrated stress area is naturally formed. The undisturbed far-field stresses away from the wellbore may remain the same. The concentrated stress area is narrow and is proximate to the wellbore. The concentrated stress surrounding the wellbore gradually changes to the magnitude of the far field stresses within only two to three times the wellbore radius. For instance, if a wellbore is 4.25 inches in radius, the concentrated stress area will often dissipate in about 10 inches from the wellbore wall. This concentrated near-wellbore stress, sometimes referred to as “hoop stress”, can be much larger than the far-field stresses. Though this stress concentration area is only around the wellbore, it can enable a wellbore to hold much higher pressure than without it. Due to the variation of stresses in different formations, some intervals of a wellbore may be capable of holding more pressure than others. In some cases, drilling operators have been unknowingly relying on this near-wellbore stress riser for containing higher wellbore pressure.
Generally, drilling operations can be conducted in many different rock formations. Some rock can be very brittle. Under tectonic stresses, many rock formations are fractured. When the surfaces of these fractures are mismatched or there is debris inside the fractures, the fractures may not close properly even under high formation stresses and may leak or be hydraulically conductive to the drilling fluid. Typically, it does not require a long leaking fracture to connect a wellbore to its far field low stress environment and cause wellbore fluid to bypass this narrow near-wellbore stress concentration region. Generally, when this occurs, the high hoop stress can no longer help the wellbore to hold higher pressure any more. How much pressure a wellbore interval can contain is defined by the weakest formation. Only one leaking fracture penetrating a wellbore can substantially lower the pressure containment for the entire wellbore interval.
Furthermore, even when a leaking fracture is very short, such as only 0.1 inch long or a small crack, studies (Wang, et al., “Fractured Wellbore Stress Analysis: Sealing Cracks to Strengthen a Wellbore,” SPE/IADC (Society of Petroleum Engineers/International Association of Drilling Contractors) 104947, published at the 2007 SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 20-22 Feb. 2007) show it can still substantially lower the wellbore pressure containment. Such a crack can be easily extended further at a pressure much lower than the near wellbore stress to connect to the low far-field stress region. Similarly, other flaws such as notches caused by drill bits may also lower the pressure required to induce a fracture.
When there is a large stress concentration around a wellbore, studies (Wang, et al., “Fractured Wellbore Stress Analysis: Sealing Cracks to Strengthen a Wellbore,” SPE/IADC (Society of Petroleum Engineers/International Association of Drilling Contractors) 104947, published at the 2007 SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 20-22 Feb. 2007) have shown that sealing these leaking fractures can substantially improve wellbore pressure containment. Sealing leaking fractures can put the otherwise bypassed higher near wellbore stresses into use to help the wellbore to hold much higher pressure than the lower undisturbed far field stresses alone can. Sealing leaking fractures can strengthen a wellbore even substantially beyond what its natural hoop stress can provide. When sealing fractures for a higher wellbore strength or wellbore pressure containment is achieved by a fracture sealing fluid, such a sealing fluid is referred to as a wellbore strengthening fluid.
There are known methods in the art related to the sealing of the fracture and the inherent strengthening of the wellbore thereby. In one conventional method, particulates are added to drilling fluid in an attempt to seal off a lost circulation zone to stop lost circulation. For example, in a conventional method, particulates are arbitrarily added to drilling fluid to seal fractures. However, arbitrary particulates or particulates defined based on an empirical equation added to drilling fluid to seal off fractures are typically inefficient and unreliable due to lack of knowledge regarding certain fracture properties, including fracture width, especially after some fluid has invaded into the fracture.
When there is not enough hoop stress around the wellbore, simply sealing a fracture can not strengthen a wellbore. In this case, in another conventional method of strengthening the wellbore when there is not enough stress concentration around a wellbore, a fracture is purposely induced and propped and sustained to increase the hoop stress of the wellbore correspondingly. Based on its established fracture propping model, needed increase in wellbore strength equals the induced additional hoop stress, which is correlated to a certain propped fracture width. This width and induced stress is to be sustained by fracture propping particulates matching the fracture width. Based on this fracture width sustaining model, the number of the propping particulates in drilling fluid matching the size of the needed fracture width is calculated. The concentration of a particulate composition is then calculated based on the percentage of the propping particulates in the particulate composition.
In the above mentioned method, apparently too large of particulates can not be forced into small fractures and too small of particulates do not have enough propping functions. This method requires an accurate determination of the required fracture width and prefers particulates matching the desired fracture propping width.
The data provided in the directly aforementioned conventional method is unlikely to be available and completely accurate at all times. For example, when an unknown fracture length is estimated, it results in the predicted fracture width also being estimated. Such an estimate can skew the data on which the models are based, which in turn affects the predicted fracture width. The skewed data can be problematic in that the optimal size of the propping particulates for inducing and maintaining the increased hoop stress is based on the predicted fracture width. If the fracture width in fact is much larger than predicted, the propping particulates may not stay inside the fracture mouth and may not induce enough hoop stress. If the fracture width is much smaller than predicted, the propping particulates may not be able to enter the fracture for the propping effect and no additional hoop stress can be induced. Moreover, if the fracture width after the particulate composition is circulated is determined to be different from the previously predicted fracture width, typically the particulate composition has to be changed to remain optimized. However, changing the particulate composition at a rig site can have enormous logistical and cost issues and is generally avoided since each job may call for an amount of 150,000 to 500,000 pounds of such particulates.
For any case, in the above mentioned method, the needed fracture width is determined after all the data are defined. It is therefore unpractical to define an optimized propping composition before the fracture width is defined. Every case will therefore require an optimized composition to be customized and that it is impossible to for a composition to be made ready ahead of time results in a low efficiency.
Furthermore, during drilling a large quantity of drilled cuttings are generated and carried back by the circulated drilling fluid. At the surface, solid control systems such as shale shakers with screens are used to separate and dispose of the cuttings from the drilling fluid to keep the needed properties from deteriorating. However, when particulates are added into the drilling fluid, these cuttings are mixed with the added particulates. In order to keep the added particulates in the drilling fluid, the mesh size of the screens has to be designed to ensure the added particulates can pass through so that it will not be discarded together with the drilled cuttings and lower the performance of the designed particulate fluid. If the particulate size of the particulate fluid is changed, the mesh screen may have to be changed in order to properly screen out the cuttings, while retaining the particulates. Such screen mesh sizes may be unavailable, as there are only a few mesh sizes commercially available. If the mesh size is inadequate for the particulate size distribution, the composition of the particulate fluid will be compromised and unlikely to provide the intended benefits.
Still further, in the conventional method wherein a fracture propping composition for inducing additional hoop stress is designed based on a derived fracture width based on other well conditions such as an estimated fracture length, there is no appropriate criterion for quantifying its propping performance with a lab test for the derived fracture width. Without such a criterion, quality control for a fracture propping composition cannot be meaningfully implemented. Particulates normally are manufactured out of such as hammer mills. Due to the unevenness of the raw materials and the processing method, the particulates manufactured tend to vary much from batch to batch. A lab test is important for quality controlling a formulated particulate fluid on its needed function.
In view of the above, a need still exists for an inexpensive and time-efficient flexible method to implement at a rig site to substantially strengthen a portion of a wellbore of a hydrocarbon well. It would be further desirable to transform well bore fluid to include particulates of a suitable size and quantity to reinforce a fractured zone of a well bore utilizing pumps, hoppers, blenders and well fluid holding tanks. It would further be desirable to substantially strengthen a wellbore utilizing a minimal amount of hardware and machinery, such that transport cost and time to the well site would be minimized. It would still further be desirable to strengthen a wellbore utilizing a method that does not require accurate data. It would also be desirable to utilize a particulate fluid, wherein many characteristics of the particulate fluid would remain constant throughout the strengthening process. Additionally, it would be desirable to employ a wellbore strengthening method of substantially sealing off a fracture, wherein the propping of the fracture is unnecessary. Furthermore, it would be desirable to employ a method of substantially sealing off a fracture and the wellbore such that the wellbore could contain a higher pressure therein.